Steam flooding, as a thermal enhanced oil recovery (EOR) process, has been introduced in heavy (5°-20° API) oil fields to increase recovery factors in relatively shallow and depleted formations. Heavy oils always have high viscosities that are 100 cp or greater. Steam, through its latent heat, reduces the viscosity of the oil and makes the oil moveable toward the production wellbores, through recovery mechanisms such as gravity drainage.
In thermal hydrocarbon production steam flooding operations, steam is typically generated above the ground and may be used to provide steam to one or several wells (e.g., injection wells, production wells undergoing cyclic steaming, etc.) at once. A plurality of tubulars (e.g., conduits) are installed within each well to deliver steam into the hydrocarbon bearing formation. Tubulars are inclusive of casing, liner, tubing, and conductor which are all different sizes of pipes for different oilfield wellbore applications. The wells may have a vertical, inclined, horizontal, or combination trajectories to deliver steam to the formation. Flow control devices are deployed in the plurality of tubulars to distribute steam. There are two primary methods of distributing steam for heat and flow conformance control: 1) tubing-deployment and 2) liner or casing deployment.
Tubing deployment (1) has flow control devices integrally connected to the tubing and the tubing is always deployed inside casing or liner. For tubing deployment, steam exits the tubing via a tubing deployed flow control device(s) and enters the tubing-liner annulus. After entering the tubing-liner annulus, the steam then passes through the liner and enters the openhole or formation. Packers may be used with tubing deployment to direct and control the steam movement into the formation.
Liner or casing deployment (2) has flow control devices integrally connected to the liner or casing, and the liner and casing is deployed in openhole. For liner or casing deployment, steam is delivered with open-ended tubing (i.e. without flow control devices) into the liner or casing. Steam exits the liner or casing via a liner or casing deployed flow control device(s) and enters the openhole or formation.
The flow control devices support uniform distribution of heat from the tubing into either the tubing-liner-annular space or formation. A plurality of packers may also be installed on the tubulars to effect hydraulic isolation of various wellbore segments in either the tubing-liner annulus or the liner-openhole annulus. The intent of this hydraulic isolation is the improvement of heat delivery uniformity to the wellbore-formation interface.
Many factors can negatively affect the function of the steam injection system. For example, flow control devices with large outside diameters increase friction and drag forces when inserting or pulling the tubing in a wellbore, which in turn, may increase the likelihood that the tubing and completion hardware will get stuck in a horizontal section of a wellbore (e.g., due to sand, scale, asphaltenes, etc.) and damaged due to being stuck. As another example, packers may not provide an effective hydraulic seal and may not be able to direct the steam to the targeted portion of the formation or wellbore. Non-uniform heating can substantially impact the economics of the field development, oil production response, and create non-uniform steam breakthrough in the production wellbores. As another example, the steam injectors inject the steam at high temperatures, which may result in sand influx and clogging, low cycle fatigue, and packer and liner hanger deterioration. Diagnosis of equipment integrity is crucial to ensure the reliability and integrity of the steam injection system. Furthermore, steam conformance control in the steam injection and cyclic steam stimulation wellbores is crucial for formation heat management in heavy oil fields.
Fiber optic based surveillance technology has been used by the oil and gas industry since the early 90s to try and uncover and address some of the aforementioned items in a timely manner. However, despite the improvements in underlying Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS) technology, success continues to be limited due to a variety of challenges and deficiencies in existing solutions, which include, but are not limited to: (1) conventional flow profiling algorithms that do not properly take into account the complex nature of the multi-phase steam flow and heat transfer behavior in the wellbore and formation associated with steam injection (e.g., algorithms based on Joules Thompson effect); (2) different algorithms, based on different physical assumptions (e.g., acoustic, temperature, etc.) that calculate different flow profiles with no robust way to confidently determine the most likely flow profile; (3) inability to robustly diagnose conditions in the wellbore and performance of the associated steam injection conformance control equipment; and (4) surveillance systems that require overly complex fiber optic systems that add complexity and risk to the operation of the field.
Thus, there continues to be a need for an improved manner of steam injection flow profiling.